Drill bits are commonly used for drilling bore holes or wells in earth formations. One type of drill bit is a fixed cutter drill bit which typically includes a plurality of cutting elements, or cutters, disposed within a respective cutter pocket formed within one or more blades of the drill bit.
FIG. 1 shows a perspective view of a drill bit 100, or fixed cutter drill bit 100, in accordance with the prior art. Referring to FIG. 1, the drill bit 100 includes a bit body 110 that is coupled to a shank 115 and is designed to rotate in a counter-clockwise direction 190. The shank 115 includes a threaded connection 116 at one end 120. The threaded connection 116 couples to a drill string (not shown) or some other equipment that is coupled to the drill string. The threaded connection 116 is shown to be positioned on the exterior surface of the one end 120. This positioning assumes that the drill bit 100 is coupled to a corresponding threaded connection located on the interior surface of a drill string (not shown). However, the threaded connection 116 at the one end 120 is alternatively positioned on the interior surface of the one end 120 if the corresponding threaded connection of the drill string, or other equipment, is positioned on its exterior surface in other exemplary embodiments. A bore (not shown) is formed longitudinally through the shank 115 and extends into the bit body 110 for communicating drilling fluid during drilling operations from within the drill string to a drill bit face 111 via one or more nozzles 114 formed within the bit body 110.
The bit body 110 includes a plurality of gauge sections 150 and a plurality of blades 130 extending from the drill bit face 111 of the bit body 110 towards the threaded connection 116, where each blade 130 extends to and terminates at a respective gauge section 150. The blade 130 and the respective gauge section 150 are formed as a single component, but are formed separately in certain drill bits 100. The drill bit face 111 is positioned at one end of the bit body 110 furthest away from the shank 115. The plurality of blades 130 form the cutting surface of the drill bit 100. One or more of these plurality of blades 130 are either coupled to the bit body 110 or are integrally formed with the bit body 110. The gauge sections 150 are positioned at an end of the bit body 110 adjacent the shank 115. The gauge section 150 includes one or more gauge cutters (not shown) in certain drill bits 100. The gauge sections 150 typically define and hold the full hole diameter of the drilled hole. Each of the blades 130 and gauge sections 150 include a leading edge section 152, a face section 154, and a trailing edge section 156. The face section 154 extends from one end of the trailing edge section 156 to an end of the leading edge section 152. The leading edge section 152 faces in the direction of rotation 190. The blades 130 and/or the gauge sections 150 are oriented in a spiral configuration according to some of the prior art. However, in other drill bits, the blades 130 and/or the gauge sections 150 are oriented in a non-spiral configuration. A junk slot 122 is formed, or milled, between each consecutive blade 130, which allows for cuttings and drilling fluid to return to the surface of the wellbore (not shown) once the drilling fluid is discharged from the nozzles 114 during drilling operations.
A plurality of cutters 140 are coupled to each of the blades 130 within a respective cutter pocket 160 formed therein. The cutters 140 are generally formed in an elongated cylindrical shape; however, these cutters 140 can be formed in other shapes, such as disc-shaped or conical-shaped. The cutters 140 typically include a substrate 142, oftentimes cylindrically shaped, and a cutting surface 144, also cylindrically shaped, disposed at one end of the substrate 142 and oriented to extend outwardly from the blade 130 when coupled within the respective cutter pocket 160. The cutting surface 144 can be formed from a hard material, such as bound particles of polycrystalline diamond forming a diamond table, and be disposed on or coupled to a substantially circular profiled end surface of the substrate 142 of each cutter 140. Typically, the polycrystalline diamond cutters (“PDC”) are fabricated separately from the bit body 110 and are secured within a respective cutter pocket 160 formed within the bit body 110. Although one type of cutter 140 used within the drill bit 100 is a PDC cutter; other types of cutters also are contemplated as being used within the drill bit 100. These cutters 140 and portions of the bit body 110 deform the earth formation by scraping and/or shearing depending upon the type of drill bit 100.
FIG. 2A shows a side view of the cutter pocket 160 with a cutter 140 disposed within a cavity 266 formed within the cutter pocket 160, in accordance with the prior art. FIG. 2B shows a profile view of a rear surface 243 of the PDC cutter 140 and a pocket back 262 when the PDC cutter 140 is coupled within the cutter pocket 160, in accordance with the prior art. Referring to FIGS. 2A and 2B, the typical cutter pocket 160 is formed by a machining process, or some other known process, into the blade 130 from the leading edge section 152 of the blade 130. This machining process forms a pocket back 262 and two pocket sides 264, each pocket side 264 being similar to the other, extending outwardly from the pocket back 262 towards the leading edge 152 and are positioned opposite one another. The pocket back 262 and the pocket sides 264 collectively define a cavity 266 for receiving at least a portion of the cutter 140 therein. The pocket back 262 is typically formed with a drill point 263, or cone-shaped indentation, substantially at or near a center of the pocket back 262. This drill point 263 is formed due to a point in the tool (not shown) used during the machining process. The typical cutter pocket 160 provides a “mechanical lock” to the cutter 140 when positioned within the cutter pocket 160 and facilitates coupling of the cutter 140 to the cutter pocket 160 by preventing unwanted movement of the cutter 140 within the cutter pocket 160 during the cutter coupling process, which is known to people having ordinary skill in the art. Typically, this “mechanical lock” has been achieved by forming pocket sides 264 that in combination wrap over more than half of the barrel diameter of the cutter 140. As seen in FIG. 2B, the circumference of the rear surface 243 of the cutter 140 typically overlaps with the circumference of the pocket back 262. Also, each of the pocket sides 264 typically extend circumferentially around a portion of the substrate 142 to be at least greater than seventy percent of the cutter girth 241 as seen when the cutter 140 is positioned within the cutter pocket 160. Typically, the upper edge of the pocket sides 264 is elevationally constant with respect to the circumferential portion of the cutter 140. When coupling the cutter 140 within the cutter pocket 160, the cutter 140 is positioned within the cavity 266 and oriented so that the cutting surface 144 extends outwardly from the leading edge section 152 of the blade 130. Once properly positioned, a bonding material (not shown), such as an adhesive or a braze alloy, is used to fix the cutter 140 within the cutter pocket 160. However, these drill points 263, as mentioned above, formed within the cutter pocket 160 during the machining process inhibit proper flow of the bonding material due to the increase in spacing between the rear surface 243 of the cutter 140 and surface of the drill point 263, and hence, create a weakness in the bond between the cutter 140 and the cutter pocket 160. Further, since the pocket back 262 is typically formed to be one hundred percent of the cutter girth 241 if hardfacing material is added to the top of the pocket back 262/blade top, then this hardfacing material would become a penetration limiter and also a catch point for debris from the wellbore.
The drawings illustrate only exemplary embodiments of the invention and are therefore not to be considered limiting of its scope, as the invention may admit to other equally effective embodiments.